Drilling fluid for hydrogen sulfide treatment

ABSTRACT

A method of drilling a subterranean geological formation is described. The method includes driving a drill bit to form a wellbore into the subterranean geological formation thereby producing a formation fluid including hydrogen sulfide (H2S). The method includes injecting a drilling fluid into the subterranean geological formation through the wellbore. The drilling fluid composition includes 0.25 to 2 wt. % of a primary H2S scavenger which is potassium permanganate. The drilling fluid composition includes an invert emulsion includes a continuous phase including palm oil and a dispersive phase including water. The potassium permanganate present in the drilling fluid composition reacts with the H2S present in the formation fluid to produce a dispersion of manganese-containing particles which are at least one selected from the group consisting of manganese sulfide and manganese sulfate.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a Divisional of U.S. application Ser. No.17/751,822, now allowed, having a filing date of May 24, 2022. Thepresent application is related to applications titled “Diesel InvertEmulsion Hydrogen Sulfide Mitigating Drilling Fluid and Method ofDrilling Subterranean Geological Formation” (U.S. application Ser. No.17/751,764), “Mineral Oil Invert Emulsion Hydrogen Sulfide MitigatingDrilling Fluid and Method of Drilling Subterranean Geological Formation”(U.S. application Ser. No. 17/751,785), and “Vegetable Oil InvertEmulsion Hydrogen Sulfide Mitigating Drilling Fluid and Method ofDrilling Subterranean Geological Formation”; U.S. application Ser. No.17/751,809.

BACKGROUND Technical Field

The present disclosure is directed to a method of drilling asubterranean geological formation with a drilling fluid, andparticularly, to the method of drilling the subterranean geologicalformation with a drilling fluid composition including a hydrogen sulfide(H₂S) scavenger.

DESCRIPTION OF RELATED ART

The “background” description provided herein is for the purpose ofgenerally presenting the context of the disclosure. Work of thepresently named inventors, to the extent it is described in thisbackground section, as well as aspects of the description which may nototherwise qualify as prior art at the time of filing, are neitherexpressly or impliedly admitted as prior art against the presentinvention.

Driving a drill bit to form a wellbore into a subterranean geologicalformation may lead to production of a fluid including toxic hydrogensulfide (H₂S). The H₂S can be poisonous to humans and animals. Adrilling fluid, also referred to as the drilling mud, is used in welldrilling applications. The drilling fluid lubricates and cools the drillbit, removes drilling cuttings and solid suspensions, seals a permeableformation, and prevents formation damage by controlling a subsurfacepressure. The drilling fluid is one or more of water-based muds (WBMs)and oil-based muds (OBMs). The WBMs react or interfere with a shaleformation. Therefore, the OBMs are preferred over the WBMs. However,current OBMs of invert emulsions are devoid of potent H₂S scavengers.

Lehrer et al. (U.S. Pat. No. 9,587,181) disclosed the use ofwater-soluble aldehyde and transition metal salts for the H₂S scavengingfrom aqueous fluids. Garrett et al. [Garrett, R. L.; Clark, R. K.;Carney, L. L.; Grantham, C. K., 1979, Chemical scavengers for sulfidesin water-base drilling fluids, Journal of Petroleum Technology, 31(6):787-796] used zinc compounds (e.g., zinc carbonate and zinc oxide) asthe H₂S scavengers. Paulsen et al. (U.S. Pat. No. 6,881,389) proposed aprocess for the removal of the H₂S or carbon dioxide from natural gasvia absorption and disassociation utilizing a seawater contact system.Muller et al. (U.S. Pat. No. 7,235,697) disclosed a process forproducing thiols, thioethers and disulfides by reacting olefins with theH₂S in the presence of water and carbon dioxide. Keller et al. (U.S.Pat. No. 6,946,111) disclosed a process for the H₂S removal from a gasstream via a reaction of the H₂S with O₂ over a suitable catalyst.McManus (U.S. Pat. No. 5,215,728) disclosed a method for the H₂Sscavenging using polyvalent metal redox absorption solution.

However, none of the references describe methods including OBMs ofinvert emulsions which may include efficient H₂S scavengers.Accordingly, it is an object of the present disclosure to providemethods to overcome the aforementioned limitations.

SUMMARY

In an exemplary embodiment, a method of drilling a subterraneangeological formation is described. The method includes driving a drillbit to form a wellbore into the subterranean geological formationthereby producing a formation fluid including hydrogen sulfide (H₂S) andinjecting a drilling fluid into the subterranean geological formationthrough the wellbore. The drilling fluid composition includes 0.25 to 2wt. % of a primary H₂S scavenger, which is potassium permanganate, andan invert emulsion. The invert emulsion includes a continuous phaseincluding palm oil, and a dispersive phase including water. Thepotassium permanganate present in the drilling fluid composition reactswith the H₂S present in the formation fluid to produce a dispersion ofmanganese-containing particles which are at least one selected from thegroup consisting of manganese sulfide and manganese sulfate.

In some embodiments, the drilling fluid composition is injected into thesubterranean geological formation through the wellbore to maintain apressure in the wellbore that is higher than a static pressure of thesubterranean geological formation.

In some embodiments, the formation fluid is at least one selected from asour gas and a sour crude oil.

In some embodiments, the potassium permanganate present in the drillingfluid reacts with 0.05 to 0.20 equivalents of the H₂S by weight.

In some embodiments, the drilling fluid further includes 2 to 4 wt. % aprimary emulsifier; 0.25 to 0.50 wt. % a secondary emulsifier; 4 to 6wt. % a viscosifier; 0.4 to 0.7 wt. % at least one fluid loss preventionagent; 0.6 to 1.0 wt. % a pH adjusting agent including an alkali metalbase; 0.25 to 2 wt. % a clay stabilizer including an alkali metal halidesalt; 0.05 to 0.5 wt. % a filtration rate agent, and 1 to 3 wt. % aweighting agent.

In some embodiments, the drilling fluid has a maximum oil separation ofless than 2% after 20 days.

In some embodiments, the invert emulsion includes 75 to 85 vol % palmoil and 15 to 25 vol % water.

In some embodiments, the primary emulsifier is sorbitan oleate.

In some embodiments, the secondary emulsifier is a rhamnolipid.

In some embodiments, the viscosifier is bentonite.

In some embodiments, the fluid loss prevention agent is at least oneselected from the group consisting of corn starch and poly(vinylbutyral)-co-vinyl alcohol-co-vinyl acetate (PVBA).

In some embodiments, the fluid loss prevention agent is a mixture of 85to 90 wt. % the corn starch and 10 to 15 wt. % the PVBA, each based on atotal weight of the mixture.

In some embodiments, the alkali metal base is sodium hydroxide.

In some embodiments, the alkali metal halide salt is potassium chloride.

In some embodiments, the filtration rate agent is sodium carbonate.

In some embodiments, the weighting agent is hydrophobic metallic zincnanoparticles.

In another exemplary embodiment, a drilling fluid is described. Thedrilling fluid includes 0.25 to 2 wt. % of a primary H₂S scavenger,which is potassium permanganate and an invert emulsion. The invertemulsion includes a continuous phase including palm oil and a dispersivephase including water. The drilling fluid is configured to produce uponcontact with H₂S, a dispersion of the manganese-containing particleswhich are at least one selected from the group consisting of manganesesulfide and manganese sulfate.

In some embodiments, the drilling fluid includes 2 to 4 wt. % a primaryemulsifier, 0.25 to 0.50 wt. % a secondary emulsifier, 4 to 6 wt. % aviscosifier, 0.4 to 0.7 wt. % at least one fluid loss prevention agent,0.6 to 1.0 wt. % a pH adjusting agent including an alkali metal base,0.25 to 2 wt. % a clay stabilizer including an alkali metal halide salt,0.05 to 0.5 wt. % a filtration rate agent, and 1 to 3 wt. % a weightingagent.

In some embodiments, the primary emulsifier is sorbitan oleate, thesecondary emulsifier is a rhamnolipid, the viscosifier is bentonite, thefluid loss prevention agent is at least one selected from the groupconsisting of corn starch and PVBA, the alkali metal base is sodiumhydroxide, the alkali metal halide salt is potassium chloride, thefiltration rate agent is sodium carbonate, and the weighting agent ishydrophobic metallic zinc nanoparticles.

In some embodiments, the drilling fluid has a maximum oil separation ofless than 2% after 20 days.

The foregoing general description of the illustrative present disclosureand the following detailed description thereof are merely exemplaryaspects of the teachings of this disclosure and are not restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of this disclosure and many of theattendant advantages thereof will be readily obtained as the samebecomes better understood by reference to the following detaileddescription when considered in connection with the accompanyingdrawings, wherein:

FIG. 1 is a schematic flow chart of a method of drilling a subterraneangeological formation, according to certain embodiments; and

FIG. 2 is a graph depicting a breakthrough curve of hydrogen sulfide,according to certain embodiments.

DETAILED DESCRIPTION

In the drawings, like reference numerals designate identical orcorresponding parts throughout the several views. Further, as usedherein, the words “a,” “an” and the like generally carry a meaning of“one or more,” unless stated otherwise.

Furthermore, the terms “approximately,” “approximate,” “about,” andsimilar terms generally refer to ranges that include the identifiedvalue within a margin of 20%, 10%, or preferably 5%, and any valuesthere between.

According to a first aspect, the present disclosure relates to a methodof drilling a subterranean geological formation.

The method involves driving a drill bit to form a wellbore into thesubterranean geological formation thereby producing a formation fluidincluding hydrogen sulfide (H₂S) and injecting a drilling fluid(otherwise referred to as the drilling mud) into the subterraneangeological formation through the wellbore. The drilling fluidcomposition includes 0.25 to 2 wt. % of a primary H₂S scavenger, whichis potassium permanganate, and an invert emulsion. The invert emulsionincludes a continuous phase including palm oil, and a dispersive phaseincluding water. The potassium permanganate present in the drillingfluid composition reacts with the H₂S present in the formation fluid toproduce a dispersion of manganese-containing particles which are atleast one selected from the group consisting of manganese sulfide andmanganese sulfate.

FIG. 1 illustrates a schematic flow chart of a method 100 of drillingthe subterranean geological formation. The order in which the method 100is described is not intended to be construed as a limitation, and anynumber of the described method steps can be combined in any order toimplement the method 100. Additionally, individual steps may be removedor skipped from the method 100 without departing from the spirit andscope of the present disclosure.

At step 102, the method 100 includes driving a drill bit into thesubterranean geological formation. This may be accomplished using anysuitable equipment or technique known to one of ordinary skill in theart. There are no specific limitations placed on, for example, the typeof drill bit used, the equipment used in the driving, or other suitableequipment used such as positioning devices, monitoring devices, groundscanning devices, or the like. In some embodiments, a site of interestis first identified, and a drill truck drills a starter hole. Then, thewellbore is drilled with the drill bit coupled to a motor. The wellboremay be drilled to a depth of at least 1,000 m, preferably at least 2,000m, preferably at least 5,000 m, preferably at least 7,000 m, but no morethan 10,000 m. In some embodiments, a site of interest is firstidentified, and a drill truck drills a starter hole. The wellbore can bedrilled with the drill bit coupled to a motor. The drill bit and themotor used in this disclosure are not meant to be limiting and variousdrill bits and motors may be utilized. In some embodiments, the drillbit may include, but is not limited to a twist drill, counterbore,countersink and flat bottom boring. The method 100 includes driving thedrill bit to form a wellbore into the subterranean geological formation.The subterranean geological formation may include, but is not limitedto, an oil reservoir, a gas reservoir, a mixed hydrocarbon bearingsubterranean formation, a saline formation, or a coal bed. In thepresent disclosure, the wellbore may be a portion of an oil well or agas well, i.e. a borehole, that faces a formation matrix of thesubterranean geological formation. In some embodiments, the wellboreincludes casing that is made up of one or more metal selected from oneor more of stainless steel, aluminum, fiberglass and titanium. In someembodiments, the wellbore may be a horizontal wellbore or a multilateralwellbore. The horizontal wellbore may include one or more sectionslocated parallel to a ground surface.

The driving of the drill bit to form the wellbore into the subterraneangeological formation thereby produces a formation fluid. The compositionof the formation fluid that may be produced during the drilling maydepend on the type of the subterranean geological formation. In someembodiments, the formation fluid is at least one selected from a sourgas and a sour crude oil. The sour gas is a natural gas including anamount of the H₂S. In some embodiments, the formation fluid may include,but is not limited to, natural gas (i.e., primarily methane),hydrocarbon or non-hydrocarbon gases (including condensable andnon-condensable gases), light hydrocarbon liquids, heavy hydrocarbonliquids, rock, oil shale, bitumen, oil sands, tar, coal, and/or water.Further, the non-condensable gases may include, but are not limited tohydrogen, carbon monoxide, carbon dioxide and methane. In some otherembodiments, the formation fluid may be in the form of a gaseous fluid,a liquid, or a double-phase fluid. In some embodiments, the formationfluid includes the H₂S. Microorganisms such as sulfate reducing bacteriamay generate the H₂S in gas and oil reservoirs.

At step 104, the method 100 includes injecting the drilling fluid intothe subterranean geological formation through the wellbore. In someembodiments, the drilling fluid composition is injected into thesubterranean geological formation through the wellbore to maintain atemperature and a pressure in the wellbore that is higher than a staticpressure of the subterranean geological formation. A formation fluid maybe produced during or after the drilling. During the drilling, thedrilling fluid composition is injected optionally into the subterraneangeological formation through the well bore to lubricate and cool thedrill bit and to remove drilling cuttings. In some embodiments, thedrilling fluid composition is injected at a flow rate ranging from 12 to26 L/s, preferably 15 to 22 L/s, more preferably 17 to 20 L/s.

In some embodiments, the method comprises cycling the drilling fluidcomposition described below with a different drilling fluid composition,such as one which does not contain a H₂S scavenger. That is, for aportion of the drilling, the drilling fluid composition described belowis used and for a different portion of the drilling, the other drillingfluid composition is used. Such portions may be performed in anysuitable pattern and with any suitable period or frequency. For example,when a level of H₂S in a formation fluid or other suitable fluid risesto a threshold level, the drilling fluid composition described below maybe used. The drilling fluid composition described below may be useduntil the level of H₂S drops below the threshold level. Such cycling maybe advantageous for reasons such as safety of workers associated withthe drilling operations, avoiding corrosion or other degradation ofdrilling hardware or other wellbore hardware, or economic factors suchas cost. In some embodiments, the other drilling fluid composition has acomposition similar to that of the drilling fluid composition describedbelow but which does not comprise the potassium permanganate primary H₂Sscavenger. The cycling may comprise addition of the potassiumpermanganate, added in any suitable form, to the other drilling fluidcomposition to form the drilling fluid composition described below. Thatis, the cycling may involve the addition of “pulses” of potassiumpermanganate into a drilling fluid to form the drilling fluidcomposition described below.

In another embodiment a permanganate-containing composition is injectedinto a wellbore in the form of a gel or suspension. The permanganate,prior to injection into the well, is mixed as an aqueous solution athigh turbulence and shear with an oil phase together in the presence ofan excess amount of a viscoelastic surfactant. A preferable surfactantis CTAB modified as a gemini from or two-tailed surfactant molecule,preferably in an amount of 5-25%, 10-20% or about 15% by weight of thetotal weight of the composition. When mixed under high shear thepermanganate-containing water solution, the oil and the surfactant forma gel or micelle-containing composition. This in turn is injectedimmediately after formation into the wellbore such that the micelle orgel characteristic of the composition is maintained until thepermanganate-containing composition reaches a target location in thewellbore. Preferably the permanganate-containing composition is madecontinuously during the injection and is injected into the wellboreimmediately and continuously while being formed.

The drilling fluid composition includes 0.25 to 2 wt. %, preferably 0.35to 1.75, preferably 0.50 to 1.5 wt. %, preferably 0.55 to 1.45 wt. %,preferably 0.60 to 1.40 wt. %, preferably 0.65 to 1.35 wt. %, preferably0.70 to 1.30 wt. %, preferably 0.75 to 1.25 wt. %, preferably 0.80 to1.20 wt. %, preferably 0.85 to 1.15 wt. %, preferably 0.90 to 1.10 wt.%, preferably 0.95 to 1.05 wt. %, preferably 1 wt. % of the primary H₂Sscavenger, which is the potassium permanganate. In some embodiments, thepotassium permanganate present in the drilling fluid reacts with 0.05 to0.20 equivalents of the H₂S, preferably 0.075 to 0.185 equivalents ofthe H₂S, preferably 0.1 to 0.175 equivalents of H₂S, preferably 0.125 to0.150 equivalents of H₂S by weight. The potassium permanganate presentin the drilling fluid composition reacts with the H₂S present in theformation fluid to produce the dispersion of the manganese-containingparticles which are at least one selected from the group consisting ofthe manganese sulfide and the manganese sulfate. In some embodiments,concentration of the potassium permanganate may be as high as asolubility limit in the drilling fluid at a given temperature andpressure.

The primary H₂S scavenger (i.e. the potassium permanganate) can bepresent in or added to the drilling fluid composition in any suitableform. In some embodiments, the potassium permanganate is present in oradded to the drilling fluid composition in an encapsulated form. Such anencapsulated form may be characterized by particles or granules ofpotassium permanganate which are surrounded by a coating of anencapsulating agent. Examples of encapsulating agents include, but arenot limited to polymers such as polyvinyl acetate, polyethylene oxide,polycaprolactone, polylactic acid, polymethyl methacrylate, and thelike; waxes such as paraffin wax, beeswax, soy wax, carnauba wax, andthe like; and mixtures thereof. Removal or degradation (e.g. dissolving)of the encapsulating agent may occur on incorporation or addition to thedrilling fluid composition, or on some trigger, such as the introductionof a specific encapsulating agent remover or degrader. This removal ordegradation may result in the encapsulating agent being present in thedrilling fluid composition. The encapsulating agent may be present in astate such that is no longer forms capsules. In some embodiments, thepotassium permanganate is present in or added to the drilling fluidcomposition in a supported form. Such a supported from may becharacterized by particles or granules of potassium permanganate presenton the surface of or in pores of a suitable inorganic support. Examplesof such inorganic supports include, but are not limited to porous silicaand porous alumina. In some embodiments, the particles or granules ofpotassium permanganate are released from the inorganic support uponaddition to or incorporation in the drilling fluid composition. In someembodiments, the particles or granules of potassium permanganate arereleased from the inorganic support upon addition of specific supportrelease agent. In some embodiments, the particles or granules ofpotassium permanganate are released upon reaction with hydrogen sulfide.In some embodiments, the particles or granules of potassium permanganatereact with hydrogen sulfide without being released from the support.Encapsulated or supported forms of potassium permanganate may beadvantageous for storage or for use in the cycling of drilling fluidcomposition described above. Such forms may further be advantageous forincreasing the safety of the drilling fluid composition or thepreparation thereof, for example by limiting exposure of workers orother personnel to solid or liquid forms of potassium permanganatecapable of harming said personnel.

In some embodiments, the drilling fluid further comprises a secondaryH₂S scavenger. In some embodiments, the secondary H₂S scavenger mayinclude copper compounds such as copper oxide, copper sulfate, coppermolybdate, copper hydroxide, copper halide, copper carbonate, copperhydroxy carbonate, copper carboxylate, copper phosphate, copper hydratesand derivatives thereof; calcium salts, cobalt salts, nickel salts, leadsalts, tin salts, zinc salts, iron salts, manganese salts, zinc oxide,iron oxides, manganese oxides, triazine, monoethanolamine,diethanolamine, caustic soda, and combinations thereof.

The drilling fluid includes an invert emulsion. Invert emulsionscomprise a dispersive phase and a continuous phase. The dispersive phaseis dispersed through the continuous phase as droplets, which arestabilized by primary and secondary emulsifiers of the drilling fluid.Hereinafter, the primary and secondary emulsifiers are collectivelyreferred to as the ‘emulsifiers’ or ‘surfactants’ and individuallyreferred to as the ‘emulsifier’ or ‘surfactant’, unless otherwisespecified. In some embodiments, the continuous phase includes theprimary emulsifier. In some embodiments, the dispersive phase includesthe secondary emulsifier. In some embodiments, the dispersive phase alsoincludes the H₂S scavenger.

The invert emulsion includes a continuous phase comprising palm oil anda dispersive phase comprising water. In some embodiments, the palm oilmay be collected from restaurants, kitchens. The palm oil may be a new(i.e. unused in cooking) palm oil, or may be a used palm oil. The usedpalm oil may further comprise components related to or formed by theaction of the cooking on the oil as part of normal cooking operation.Such components may be formed by, for example, oxidative processes,heating, or reaction with metal or non-metal components of the cookwareor other ingredients used in cooking. In general, the water may be anywater containing solution, including saltwater, hard water, and/or freshwater. For purposes of this description, the term “saltwater” mayinclude saltwater with a chloride ion content of between about 6000 ppmand saturation, and is intended to encompass seawater and other types ofsaltwater including groundwater containing additional impuritiestypically found therein. The term “hard water” may include water havingmineral concentrations between about 2000 mg/L and about 300,000 mg/L.The term “fresh water” may include water sources that contain less than6000 ppm, preferably less than 5000 ppm, preferably less than 4000 ppm,preferably less than 3000 ppm, preferably less than 2000 ppm, preferablyless than 1000 ppm, preferably less than 500 ppm of salts, minerals, orany other dissolved solids. Salts that may be present in saltwater, hardwater, and/or fresh water may be, but are not limited to, cations suchas sodium, magnesium, calcium, potassium, ammonium, and iron, and anionssuch as chloride, bicarbonate, carbonate, sulfate, sulfite, phosphate,iodide, nitrate, acetate, citrate, fluoride, and nitrite. In someembodiments, the dispersive phase may include salt water. In someembodiments, the dispersive phase may include hard water. In someembodiments, the dispersive phase may include fresh water.

The drilling fluid composition also includes the invert emulsionincluding the continuous phase including the palm oil and the dispersivephase including the water. In some embodiments, the invert emulsionincludes 75 to 85 vol %, preferably 77.5 to 82.5 vol %, preferably 80vol % palm oil and 15 to 25 vol %, preferably 17.5 to 22.5 vol %,preferably 20 vol % water.

In general, the primary and/or secondary emulsifier may be a surfactant.In general, the surfactants may be a nonionic surfactant, an anionicsurfactant, a cationic surfactant, a viscoelastic surfactant, or azwitterionic surfactant. Anionic surfactants contain anionic functionalgroups at their head, such as sulfate, sulfonate, phosphate, andcarboxylate. The anionic surfactant may be an alkyl sulfate, an alkylether sulfate, an alkyl ester sulfonate, an alpha olefin sulfonate, alinear alkyl benzene sulfonate, a branched alkyl benzene sulfonate, alinear dodecylbenzene sulfonate, a branched dodecylbenzene sulfonate, analkyl benzene sulfonic acid, a dodecylbenzene sulfonic acid, asulfosuccinate, a sulfated alcohol, a ethoxylated sulfated alcohol, analcohol sulfonate, an ethoxylated and propoxylated alcohol sulfonate, analcohol ether sulfate, an ethoxylated alcohol ether sulfate, apropoxylated alcohol sulfonate, a sulfated nonyl phenol, an ethoxylatedand propoxylated sulfated nonyl phenol, a sulfated octyl phenol, anethoxylated and propoxylated sulfated octyl phenol, a sulfated dodecylphenol, and an ethoxylated and propoxylated sulfated dodecyl phenol.Other anionic surfactants include ammonium lauryl sulfate, sodium laurylsulfate (sodium dodecyl sulfate, SLS, or SDS), and related alkyl-ethersulfates sodium laureth sulfate (sodium lauryl ether sulfate or SLES),sodium myreth sulfate, docusate (dioctyl sodium sulfosuccinate),perfluorooctanesulfonate (PFOS), perfluorobutanesulfonate, alkyl-arylether phosphates, and alkyl ether phosphates.

Cationic surfactants have cationic functional groups at their head, suchas primary and secondary amines. Cationic surfactants include octenidinedihydrochloride; cetrimonium bromide (CTAB), cetylpyridinium chloride(CPC), benzalkonium chloride (BAC), benzethonium chloride (BZT),dimethyldioctadecylammonium chloride, and dioctadecyldimethylammoniumbromide (DODAB).

Zwitterionic (amphoteric) surfactants have both cationic and anionicgroups attached to the same molecule. Zwitterionic surfactants includeCHAPS (3-[(3-cholamidopropyl)dimethylammonio]-1-propanesulfonate),cocamidopropyl hydroxysultaine, ocamidopropyl betaine, phospholipids,and sphingomyelins.

Nonionic surfactants have a polar group that does not have a charge.These include long chain alcohols that exhibit surfactant properties,such as cetyl alcohol, stearyl alcohol, cetostearyl alcohol, oleylalcohol, and other fatty alcohols. Other long chain alcohols withsurfactant properties include polyethylene glycols of various molecularweights, polyethylene glycol alkyl ethers having the formulaCH₃—(CH₂)₁₀₋₁₆—(O—C₂H₄)₁₋₂₅—OH, such as octaethylene glycol monododecylether and pentaethylene glycol monododecyl ether; polypropylene glycolalkyl ethers having the formula: CH₃—(CH₂)₁₀₋₁₆—(O—C₃H₆)₁₋₂₅—OH;glucoside alkyl ethers having the formulaCH₃—(CH₂)₁₀₋₁₆—(O-glucoside)₁₋₃-OH, such as decyl glucoside, laurylglucoside, octyl glucoside; polyethylene glycol octylphenyl ethershaving the formula C₈H₁₇—(C₆H₄)—(O—C₂H₄)₁₋₂₅—OH, such as Triton X-100;polyethylene glycol alkylphenyl ethers having the formulaC₉H₁₉—(C₆H₄)—(O—C₂H₄)₁₋₂₅—OH, such as nonoxynol-9; glycerol alkyl esterssuch as glyceryl laurate; polyoxyethylene glycol sorbitan alkyl esterssuch as polysorbate, sorbitan alkyl esters, cocamide MEA, cocamide DEA,dodecyldimethylamine oxide, block copolymers of polyethylene glycol andpolypropylene glycol, such as poloxamers, and polyethoxylated tallowamine (POEA).

A dendritic surfactant molecule may include at least two lipophilicchains that have been joined at a hydrophilic center and have abranch-like appearance. In each dendritic surfactant, there may be fromabout 2 lipophilic moieties independently to about 4 lipophilic moietiesattached to each hydrophilic group, or up to about 8 lipophilic moietiesattached to the hydrophilic group for example. “Independently” as usedherein with respect to ranges means that any lower threshold may becombined with any upper threshold. The dendritic surfactant may havebetter repulsion effect as a stabilizer at an interface and/or betterinteraction with a polar oil, as compared with other surfactants.Dendritic surfactant molecules are sometimes called “hyperbranched”molecules.

A dendritic extended surfactant is a dendritic surfactant having anon-ionic spacer arm between the hydrophilic group and a lipophilictail. For example, the non-ionic spacer-arm extension may be the resultof polypropoxylation, polyethoxylation, or a combination of the two withthe polypropylene oxide next to the tail and polyethylene oxide next tothe head. The spacer arm of a dendritic extended surfactant may containfrom about 1 independently to about 20 propoxy moieties and/or fromabout 0 independently to about 20 ethoxy moieties. Alternatively, thespacer arm may contain from about 2 independently up to about 16 propoxymoieties and/or from about 2 independently up to about 8 ethoxymoieties. “Independently” as used herein with respect to ranges meansthat any lower threshold may be combined with any upper threshold. Thespacer arm extensions may also be formed from other moieties including,but not necessarily limited to, glyceryl, butoxy, glucoside, isosorbide,xylitols, and the like. For example, the spacer arm of a dendriticextended surfactant may contain both propoxy and ethoxy moieties. Thepolypropoxy portion of the spacer arm may be considered lipophilic;however, the spacer arm may also contain a hydrophilic portion to attachthe hydrophilic group. The hydrophilic group may generally be apolyethoxy portion having about two or more ethoxy groups. Theseportions are generally in blocks, rather than being randomly mixed.Further, the spacer arm extension may be a poly-propylene oxide chain.

Another type of surfactant is a viscoelastic surfactant (VES).Conventional surfactant molecules are characterized by having one longhydrocarbon chain per surfactant head-group. In a viscoelastic gelledstate these molecules aggregate into worm-like micelles. A viscoelasticgel is a gel that has elastic properties, meaning that the gel at leastpartially returns to its original form when an applied stress isremoved. Typical viscoelastic surfactants includeN-erucyl-N,N-bis(2-hydroxyethyl)-N-methyl ammonium chloride andpotassium oleate, solutions of which form gels when mixed with inorganicsalts such as potassium chloride and/or with organic salts such assodium salicylate. Previously described surfactants may also beconsidered viscoelastic surfactants.

In some embodiments, the primary emulsifier is a polyaminated fatty acidwhich emulsifies water into oil in the OBMs. The primary emulsifierincludes a lower hydrophilic-lyophilic balance (HLB) with respect to thesecondary emulsifier. In some embodiments, the drilling fluid includes 2to 4 wt. %, preferably 2.25 to 3.75 wt. %, preferably 2.5 to 3.5 wt. %,preferably 2.75 to 3.25 wt. %, preferably 2.9 to 3.1 wt. %, preferably3.0 wt. % the primary emulsifier. In some embodiments, the primaryemulsifier is sorbitan oleate (also referred to as span 80). In someembodiments, the continuous phase includes the sorbitan oleate (span80).

In some embodiments, the drilling fluid includes 0.25 to 0.50 wt. %,preferably 0.30 to 0.45 wt. %, 0.325 to 0.425 wt. %, preferably 0.35 to0.40 wt %, preferably 0.375 to 0.39 wt. %, preferably 0.38 wt. % asecondary emulsifier. In some embodiments, the secondary emulsifier is arhamnolipid biosurfactant. In some embodiments, the dispersive phaseincludes the rhamnolipid.

In some embodiments, the drilling fluid has a maximum oil separation ofless than 2%, preferably less than 1.9%, preferably less than 1.8%,preferably less than 1.7%, preferably less than 1.6%, preferably lessthan 1.5% after 20 days. The oil separation of less than 2% confirmsefficient stability of the primary and secondary emulsifiers. In someembodiments, the HLB of the rhamnolipid-sorbitan oleate is 4.5,preferably 4.0.

In some embodiments, the drilling fluid comprises a viscosifier. In someembodiments, the dispersive phase includes the viscosifier. Theviscosifier is an additive of the drilling fluid composition thatincreases viscosity of the drilling fluid. In some embodiments, thedrilling fluid includes 4 to 6 wt. %, preferably 4.25 to 5.75 wt. %,preferably 4.5 to 5.5 wt. %, preferably 4.75 to 5.25 wt. %, preferably 5wt. % the viscosifier. The term “viscosifier” as used in this disclosurerefers to an additive of the drilling fluid composition that increasesthe viscosity of the drilling fluid. Exemplary viscosifiers include, butare not limited to sodium carbonate (soda ash), bauxite, dolomite,limestone, calcite, vaterite, aragonite, magnesite, taconite, gypsum,quartz, marble, hematite, limonite, magnetite, andesite, garnet, basalt,dacite, nesosilicates or orthosilicates, sorosilicates, cyclosilicates,inosilicates, phyllosilicates, tectosilicates, kaolins, montmorillonite,fullers earth, and halloysite. In some embodiments, the viscosifier mayfurther include a natural polymer such as hydroxyethyl cellulose (HEC),carboxymethylcellulose, polyanionic cellulose (PAC), or a syntheticpolymer such as poly(diallyl amine), diallyl ketone, diallyl amine,styryl sulfonate, vinyl lactam, laponite, polygorskites (such asattapulgite, sepiolite), and combinations thereof. In some embodiments,the viscosifier may further include one or more thickening agents suchas XC-polymer, xanthan gum, guar gum, glycol, and combinations thereof.In some embodiments, the viscosifier is bentonite. The ‘bentonite’ mayrefer to potassium bentonite, sodium bentonite, calcium bentonite,aluminum bentonite, and combinations thereof, depending on the relativeamounts of potassium, sodium, calcium, and aluminum in the bentonite. Insome embodiments, the viscosifier is a corn starch.

In some embodiments, the drilling fluid comprises at least one fluidloss prevention agent. The term “fluid-loss control agent” as usedherein refers to an additive of the drilling fluid composition thatcontrols loss of the drilling fluid when injected into a subterraneangeological formation. Exemplary fluid-loss control agents include, butare not limited to starch, polysaccharides, silica flour, gas bubbles(energized fluid or foam), benzoic acid, soaps, resin particulates,relative permeability modifiers, degradable gel particulates,hydrocarbons dispersed in fluid, and one or more immiscible fluids. Insome embodiments, the dispersive phase includes the fluid lossprevention agent. In some embodiments, the drilling fluid may includemultiple fluid loss prevention agents. In some embodiments, the drillingfluid includes 0.4 to 0.7 wt. %, preferably 0.45 to 0.6 wt. % of thefluid loss prevention agent. In some embodiments, the fluid lossprevention agent is at least one selected from the group consisting ofthe corn starch and poly(vinyl butyral)-co-vinyl alcohol-co-vinylacetate (PVBA). In some embodiments, the fluid loss prevention agent isa mixture of 85 to 90 wt. % the corn starch and 10 to 15 wt. % the PVBA,each based on a total weight of the mixture.

In some embodiments, the drilling fluid comprises a pH adjusting agent,also referred to as the buffer. In some embodiments, the dispersivephase includes the pH adjusting agent. The pH adjusting agent is anadditive of the drilling fluid composition that adjusts the pH of thedrilling fluid composition. The pH adjusting agent includes an alkalimetal base. In some embodiments, the drilling fluid includes 0.6 to 1.0wt. %, preferably 0.65 to 0.95 wt. %, preferably 0.7 to 0.9 wt. % of thepH adjusting agent including the alkali metal base. The alkali metalbase may be an alkali metal hydroxide, such as potassium hydroxide,lithium hydroxide, rubidium hydroxide and cesium hydroxide. In someembodiments, the alkali metal base is sodium hydroxide. In someembodiments, the pH adjusting agent may include, but is not limited to,monosodium phosphate, disodium phosphate, sodium tripolyphosphate. Insome embodiments, the pH of the drilling fluid is acidic or neutral. Insome embodiments, the pH of the drilling fluid is basic.

In some embodiments, the drilling fluid comprises a clay stabilizercomprising an alkali metal halide salt. In some embodiments, thedispersive phase includes the alkali metal halide salt. In someembodiments, 0.25 to 2 wt. %, preferably 0.35 to 1.75, preferably 0.50to 1.5 wt. %, preferably 0.55 to 1.45 wt. %, preferably 0.60 to 1.40 wt.%, preferably 0.65 to 1.35 wt. %, preferably 0.70 to 1.30 wt. %,preferably 0.75 to 1.25 wt. %, preferably 0.80 to 1.20 wt. %, preferably0.85 to 1.15 wt. %, preferably 0.90 to 1.10 wt. %, preferably 0.95 to1.05 wt. %, preferably 1 wt. % a clay stabilizer includes the alkalimetal halide salt. The clay stabilizer is an additive of the drillingfluid composition that aids in the stabilization of shales and tocontrol swelling clays. In some embodiments, the alkali metal halidesalt is potassium chloride. In some embodiments, the alkali metal halidesalt may include, but is not limited to, sodium chloride, lithiumchloride, rubidium chloride, and cesium chloride. In some embodiments,the clay stabilizer may include an alkaline earth metal halide salt. Insome embodiments, the alkaline earth metal halide salt may include, butis not limited to, calcium chloride, and magnesium chloride.

In some embodiments, the drilling fluid comprises 0.05 to 0.5 wt. % afiltration rate agent. In some embodiments, the dispersive phaseincludes the filtration rate agent. The filtration rate agent is anadditive for aqueous drilling fluids to reduce the loss of fluids from amud cake to pores of the formation during drilling of oil and gas wells.In some embodiments, the filtration rate agent is sodium carbonate.

In some embodiments, the drilling fluid comprises a weighting agent. Theweighting agent is an agent that increases an overall density of thedrilling fluid in order to provide sufficient bottom-hole pressure toprevent an unwanted influx of formation fluids. Examples of weightingagents include, but are not limited to, calcium carbonate, barite,sodium sulfate, hematite, siderite, ilmenite, and hydrophobic zincnanoparticles. In some embodiments, the weighting agent is hydrophobicmetallic zinc nanoparticles. In some embodiments, the continuous phaseincludes the hydrophobic metallic zinc nanoparticles. In someembodiments, the drilling fluid includes 1 to 3 wt. %, preferably 1.25to 2.75 wt. %, preferably 1.5 to 2.5 wt. %, preferably 1.75 to 2.25 wt.%, preferably 1.9 to 2.1 wt. %, preferably 2.0 wt. % of the weightingagent.

In some embodiments, the drilling fluid further comprises adeflocculant. Deflocculant is an additive of the drilling fluidcomposition that prevents a colloid from coming out of suspension orslurries. In some embodiments, the deflocculant may include, but is notlimited to, an anionic polyelectrolyte, for example, acrylates,polyphosphates, lignosulfonates (LS), or tannic acid derivatives, forexample, quebracho.

In some embodiments, the drilling fluid further comprises a lubricant.In some embodiments, LUBE 10170B may be used as the lubricant. In someembodiments, the lubricant may include, but is not limited to,polyalpha-olefin (PAO), synthetic esters, polyalkylene glycols (PAG),phosphate esters, alkylated naphthalenes (AN), silicate esters, ionicfluids, and multiply alkylated cyclopentanes (MAC).

In some embodiments, the drilling fluid further comprises a crosslinker.The crosslinker is an additive of the drilling fluid composition thatcan react with multiple-strand polymers to couple molecules together,thereby creating a highly viscous fluid, with a controllable viscosity.The crosslinker may include, but is not limited to, metallic salts, suchas salts of Al, Fe, B, Ti, Cr, and Zr, or organic crosslinkers such aspolyethylene amides and formaldehyde.

In some embodiments, the drilling fluid further comprises a breaker. Thebreaker is an additive of the drilling fluid composition that provides adesired viscosity reduction in a specified period of time. The breakermay include, but is not limited to, oxidizing agents, such as sodiumchlorites, sodium bromate, hypochlorites, perborate, persulfates,peroxides, and enzymes.

In some embodiments, the drilling fluid further comprises a biocide. Thebiocide is an additive of the drilling fluid composition that may killmicroorganisms present in the drilling fluid composition. The biocidemay include, but is not limited to, phenoxyethanol, ethylhexylglycerine, benzyl alcohol, methyl chloroisothiazolinone, methylisothiazolinone, methyl paraben, ethyl paraben, propylene glycol,bronopol, benzoic acid, imidazolinidyl urea,2,2-dibromo-3-nitrilopropionamide, and 2-bromo-2-nitro-1,3-propanedial.

In some embodiments, the drilling fluid further comprises a corrosioninhibiting agent. The corrosion inhibiting agent is a chemical compoundthat decreases the corrosion rate of a material, more preferably, ametal or an alloy, that comes into contact with the drilling fluid. Insome embodiments, the corrosion inhibiting agent may include, but is notlimited to, imidazolines, and amido amines. In some embodiments, thecorrosion inhibiting agent may include, but is not limited to, oxides,sulfides, halides, nitrates, preferably halides, of metallic elements ofgroup Ma to Via such as SbBr₃.

In some embodiments, the drilling fluid further comprises ananti-scaling agent. The anti-scaling agent is an additive of thedrilling fluid composition that inhibit the formation and precipitationof crystallized mineral salts that form scale. The anti-scaling agentmay include, but is not limited to, phosphonates, acrylicco/ter-polymers, polyacrylic acid (PAA), phosphino poly carboxylic acid(PPCA), phosphate esters, hexamethylene diamine tetrakis (methylenephosphonic acid), diethylene triamine tetra (methylene phosphonic acid),diethylene triamine penta (methylene phosphonic acid) (DETAphosphonate), bis-hexamethylene triamine pentakis (methylene phosphonicacid) (BHMT phosphonate), 1-hydroxyethylidene 1,1-diphosphonate (HEDPphosphonate), and polymers of sulfonic acid on a polycarboxylic acidbackbone. In some embodiments, the anti-scaling agent may furtherinclude phosphine, sodium hexametaphosphate, sodium tripolyphosphate andother inorganic polyphosphates, hydroxy ethylidene diphosphonic acid,butane-tricarboxylic acid, phosphonates, itaconic acid, and3-allyloxy-2-hydroxy-propionic acid. In some embodiments, the drillingfluid may include metal sulfide scale removal agents such ashydrochloric acid.

In some embodiments, the drilling fluid further comprises a chelatingagent. The chelating agent may include, but is not limited to,dimercaprol (2,3-dimercapto-1-propanol), diethylenetriaminepentaaceticacid (DTPA), hydroxyethylenediaminetriacetic acid (HEDTA), andethylenediaminetetraacetic acid (EDTA).

Concentration of components of the drilling fluid may be varied toimpart desired characteristics of the drilling fluid. For instance, theconcentration of the potassium permanganate may be adjusted according toH₂S amount that may be encountered during the wellbore drilling. Thedrilling fluid is configured to produce upon contact with the H₂S, adispersion of manganese-containing particles which are at least oneselected from the group consisting of manganese sulfide and manganesesulfate.

In some embodiments, the drilling fluid further includes 2 to 4 wt. %the primary emulsifier, 0.25 to 0.50 wt. % the secondary emulsifier, 4to 6 wt. % the viscosifier, 0.4 to 0.7 wt. % the at least fluid lossprevention agent, 0.6 to 1.0 wt. % the pH adjusting agent including thealkali metal base, 0.25 to 2 wt. % the clay stabilizer including thealkali metal halide salt, 0.05 to 0.5 wt. % the filtration rate agent,and 1 to 3 wt. % the weighting agent.

In a preferred embodiment, embodiments, the primary emulsifier is thesorbitan oleate, the secondary emulsifier is the rhamnolipid, theviscosifier is the bentonite, the fluid loss prevention agent is atleast one selected from the group consisting of the corn starch and thePVBA. In some embodiments, the fluid loss prevention agent is a mixtureof 85 to 90 wt. % the corn starch and 10 to 15 wt. % the PVBA, eachbased on a total weight of the mixture.

In some embodiments, the alkali metal base is the sodium hydroxide, thealkali metal halide salt is the potassium chloride, the filtration rateagent is the sodium carbonate, and the weighting agent is thehydrophobic metallic zinc nanoparticles.

In some embodiments, the drilling fluid has the maximum oil separationof less than 2% after 20 days. In some embodiments, the drilling fluidperforms sweetening of the sour gas. The sour gas may be bubbled intothe drilling fluid to get devoid of H₂S. The present disclosure alsorelates to the H₂S scavenging during a well stimulation.

The examples below are intended to further illustrate protocols forpreparing, characterizing, and using the drilling fluid and forperforming the method described above and are not intended to limit thescope of the claims.

Where a numerical limit or range is stated herein, the endpoints areincluded. Also, all values and subranges within a numerical limit orrange are specifically included as if explicitly written out.

Obviously, numerous modifications and variations of the presentinvention are possible in light of the above teachings. It is thereforeto be understood that, within the scope of the appended claims, theinvention may be practiced otherwise than as specifically describedherein.

EXAMPLES Example 1

In some embodiments, when the drilling fluid includes neutral and acidicmedia (i.e., pH<7.5), the potassium permanganate converts the H₂S intoelemental sulfur by oxidation according to equation (1).2KMnO₄+3H₂S→3S+2KOH+2MnO₂+2H₂O  (1)

The formed MnO₂ in equation (1) may also scavenge the H₂S according toequation (2).MnO₂+2H₂S→MnS+S+2H₂O  (2)

In some embodiments, when the drilling fluid includes alkaline media(i.e., pH≥7.5), potassium permanganate converts the H₂S into potassiumsulfate according to equation (3).4KMnO₄+2H₂S→2K₂SO₄+2MnO+2MnO₂+2H₂O  (3)

The formed MnO and MnO₂ in equations (1), (3) may also scavenge the H₂S.The reaction of MnO with the H₂S can be represented by equation (4).MnO+H₂S→MnS+H₂O  (4)

Hence, the present invention also relates to the H₂S scavenging during ametal sulfide scale removal. Capturing and converting the H₂S into anelemental sulfur or sulfates during the metal sulfide scale removalprevents the release of H₂S into the well surface. In some embodiments,the manganese sulfide produced in-situ acts as the viscosifier or theweighting agent.

Example 2

The drilling fluid includes 80 vol % (out of the total liquid volume)palm oil, 20 vol % water, 5 wt. % bentonite, 2 wt. % hydrophobic zincnanoparticles, 1 wt. % potassium chloride, 3 wt. % Span 80, 0.38 wt. %rhamnolipid biosurfactant, 1 wt. % potassium permanganate, 4.518 g/L (ofthe total liquid volume) corn starch, 0.602 g/L poly(vinylbutyral-co-vinyl alcohol-co-vinyl acetate), 0.714 g/L sodium hydroxide,and 2.50 g/L Na₂CO₃.

Example 3

H₂S scavenging tests were performed using a glass column. The glasscolumn had a fritted porous circular disk at the bottom. In thebeginning of the H₂S scavenging test, 10 grams (g) of the drilling fluidincluding 100 milligrams (mg) of the potassium permanganate was placedin the glass column. Then, a valve (below the fritted porous circulardisk) at the bottom of the glass column was opened to allow the sour gas(107.5 parts per million (ppm) H₂S, balance methane) to flow into theglass column in the form of gas bubbles. The sour gas flow rate was keptconstant at 100 milliliters per minute (mL/min). The sour gas exiting abubble column (representing a gas/oil well) is sent to an H₂S gasdetector with a detection limit of 0.5 ppm. An exit gas stream wasmonitored and the concentration of the H₂S in released gas from the wellwas continuously recorded until saturation is attained (i.e., when theH₂S in the exit gas stream was equivalent to the H₂S concentration in aninlet gas stream). Breakthrough time (i.e., when the H₂S was firstdetected in an outlet gas stream) was about 13 hours (FIG. 2 ).

Example 4

The stability of the drilling fluid was monitored for 30 days. Themaximum oil separation was less than 14%. No water or solid separationwas found.

The present disclosure provides utilization of the waste/spent cookingpalm oil for drilling applications. The present disclosure also providesthe drilling fluid which are suitable for drilling high pressure-hightemperature (HPHT) reservoirs. The drilling fluid includes highlubricity, which minimizes friction between a drill pipe and a wall ofthe wellbore. Hence, reducing the chances of the drill pipe gettingstuck with the wellbore. Moreover, the drilling fluid are also suitablefor drilling low pore formation pressures. The drilling fluid does notinterfere with formation salts. Furthermore, the drilling fluid hasproperties such as decreased fluid loss, higher penetration rates, and athinner filter cake. The drilling fluid prevents escape of the H₂S tothe well surface. The secondary emulsifier of the drilling fluid isenvironment-friendly and biodegradable surfactant. Furthermore, theemulsifiers of the drilling fluid provide stability to the drillingfluid. The drilling fluid also includes efficient rheologicalcharacteristics. Scavenging of the H₂S, while the pH of the drillingfluid is neutral and acidic, leads to the production of the elementalsulfur. The elemental sulfur produced in-situ may act as theviscosifier. The drilling fluid may effectively scavenge the H₂S at awide range of temperature. Thermal decomposition of the potassiumpermanganate starts slowly at 374 degrees Fahrenheit (° F.). Thepotassium permanganate is an effective H₂S scavenger regardless of thepH of the drilling fluid.

The invention claimed is:
 1. A drilling fluid, comprising: 0.25 to 2 wt.% of a primary hydrogen sulfide scavenger which is potassiumpermanganate; an invert emulsion, comprising: a continuous phasecomprising palm oil, and a dispersive phase comprising water, whereinthe drilling fluid is configured to produce upon contact with hydrogensulfide, a dispersion of manganese-containing particles which are atleast one selected from the group consisting of manganese sulfide andmanganese sulfate.
 2. The drilling fluid of claim 1, further comprising:2 to 4 wt. % of a primary emulsifier; 0.25 to 0.50 wt. % of a secondaryemulsifier; 4 to 6 wt. % of a viscosifier; 0.4 to 0.7 wt. % of at leastone fluid loss prevention agent; 0.6 to 1.0 wt. % of a pH adjustingagent comprising an alkali metal base; 0.25 to 2 wt. % of a claystabilizer comprising an alkali metal halide salt; 0.05 to 0.5 wt. % ofa filtration rate agent; and 1 to 3 wt. % of a weighting agent.
 3. Thedrilling fluid of claim 2, wherein: the primary emulsifier is sorbitanoleate; the secondary emulsifier is a rhamnolipid; the viscosifier isbentonite; the fluid loss prevention agent is at least one selected fromthe group consisting of the corn starch and the PVBA; the alkali metalbase is sodium hydroxide; the alkali metal halide salt is potassiumchloride; the filtration rate agent is sodium carbonate; and theweighting agent is hydrophobic metallic zinc nanoparticles.
 4. Themethod of claim 2, wherein the alkali metal base is sodium hydroxide. 5.The drilling fluid of claim 1, having a maximum oil separation of lessthan 2% after 20 days.
 6. The method of claim 1, wherein the drillingfluid further comprises: 2 to 4 wt. % of a primary emulsifier; 0.25 to0.50 wt. % of a secondary emulsifier; 4 to 6 wt. % of a viscosifier; 0.4to 0.7 wt. % of at least one fluid loss prevention agent; 0.25 to 2 wt.% of a clay stabilizer comprising an alkali metal halide salt; 0.05 to0.5 wt. % of a filtration rate agent; and 1 to 3 wt. % of a weightingagent.
 7. The method of claim 6, wherein the primary emulsifier issorbitan oleate.
 8. The method of claim 6, wherein the secondaryemulsifier is a rhamnolipid.
 9. The method of claim 6, wherein theviscosifier is bentonite.
 10. The method of claim 6, wherein the fluidloss prevention agent is at least one selected from the group consistingof corn starch and poly(vinyl butyral)-co-vinyl alcohol-co-vinyl acetate(PVBA).
 11. The method of claim 10, wherein the fluid loss preventionagent is a mixture of 85 to 90 wt. % the corn starch and 10 to 15 wt. %the PVBA, each based on a total weight of the mixture.
 12. The method ofclaim 6, wherein the alkali metal halide salt is potassium chloride. 13.The method of claim 6, wherein the filtration rate agent is sodiumcarbonate.
 14. The method of claim 6, wherein the weighting agent ishydrophobic metallic zinc nanoparticles.
 15. The method of claim 1,wherein the invert emulsion comprises 75 to 85 vol % palm oil and 15 to25 vol % water.